As a borehole is drilled it is necessary to secure the borehole walls to prevent collapsing and to provide a mechanical barrier to wellbore fluid ingress and drilling fluid egress. This is achieved by cementing in casings. Casings are tubular sections positioned in the borehole, and the annular space between the outer surface of the casing and the borehole wall is conventionally filled with a cement slurry.
After the well has been drilled to its final depth it is necessary to secure a final borehole section. This is performed by either leaving the final borehole section open (termed an open hole completion), or by lining the final borehole section with a tubular such as a liner (hung off the previous casing) or casing (extending to the surface), whereby the annular space between the liner or casing and the borehole is filled with a cement slurry (termed a cased hole completion).
Production tubing is then run into the lined hole and is secured at the bottom of the well with a sealing device termed a “packer” which seals the annulus so formed between the production tubing and the outer casing or liner. At the top of the well the production tubing is fixed to a wellhead/Christmas tree combination. This production tubing is used to evacuate the hydrocarbon.
In some instances instead of running a final liner string, the final borehole section is left open and screens are run. Screens are typically perforated production tubing having either slits or holes. These screens once in position act as a conduit in a procedure to fill the annular void between the borehole wall and the screen by placing sand around the screen. The sand acts as a filter and as a support to the borehole wall. The term used for this operation is “gravel packing”.
In each case centralising or otherwise locating a tubular within a borehole or within another tubular is necessary to ensure tubulars do not strike or stick against the borehole wall or wall of the other tubular, and that a substantially exact matching of consecutive tubulars positioned in the borehole is achieved, while allowing for an even distribution of materials, e.g. cement or sand, placed within the annulus formed.
Centralisers or “protectors” for drill strings or drill pipe used to aid in the directing of a drill bit within a borehole are documented. Examples are GB 2 353 549 A (WESTERN WELL TOOL), U.S. Pat. No. 6,250,405 (WESTERN WELL TOOL), and US 2004188147 (WESTERN WELL TOOL).
More recently casing centralisers have been described which aim to keep casing away from the borehole wall and/or aid the distribution of cement slurry in the annulus between the outer surface of the casing and the borehole wall. Examples of casing centralisers are given below.
U.S. Pat. No. 5,095,981 (MIKOLAJCZYK) discloses a casing centraliser comprising a circumferentially continuous tubular metal body adapted to fit closely about a joint of casing, and a plurality of solid metal blades fixed to the body and extending parallel to the axis of the body along the outer diameter of the body in generally equally spaced apart relation, each blade having opposite ends which are tapered outwardly toward one another and a relatively wide outer surface for bearing against the well-bore or an outer casing in which the casing is disposed, including screws extending threadedly through holes in at least certain of the blades and the body for gripping the casing so as to hold the centraliser in place.
EP 0 671 546 A1 (DOWNHOLE PRODUCTS) discloses a casing centraliser comprising an annular body, a substantially cylindrical bore extending longitudinally through said body, and a peripheral array of a plurality of longitudinally extending blades circumferentially distributed around said body to define a flow path between each circumferentially adjacent pair of said blades, each said flow path providing a fluid flow path between longitudinally opposite ends of said centraliser, each said blade having a radial outer edge providing a well-bore contacting surface, and said cylindrical bore through said body being a clearance fit around casing intended to be centralised by said casing centraliser, the centraliser being manufactured wholly from a material which comprises zinc or a zinc alloy.
WO 98/37302 (DOWNHOLE PRODUCTS) discloses a casing centraliser assembly comprising a length of tubular casing and a centraliser of unitary construction (that is, made in one piece of a single material and without any reinforcement means) disposed on an outer surface of the casing, the centraliser having an annular body, and a substantially cylindrical bore extending longitudinally through the body, the bore being a clearance fit around the length of the tubular casing, characterised in that the centraliser comprises a plastic, elastomeric and/or rubber material.
WO 99/25949 (BRUNEL OILFIELD SERVICES) also discloses an improved casing centraliser.
The content of the aforementioned prior art documents are incorporated herein by reference.
As is apparent from the art, many centralisers have been developed to overcome problems pertaining to centralising a tubular and distributing an annulus material. These centralisers are of unitary assembly and are made of a plastic, or more generally, a material such as zinc, steel or aluminium. However, in selecting a single material a trade-off must be made as:                (a) the chosen material must provide a low friction surface against the smooth tubular outermost surface while being strong enough to withstand abrasion from rugous borehole walls;        (b) the chosen material must act as a journal bearing once the centraliser is in its downhole location, but during the running operation it must act as a thrust bearing.Material such as plastic deforms, and may potentially ride over stop rings or casing collars. This may occur when the centraliser contacts ledges (possibly the ledges within the BOP stack cavities and wellhead) when run in a cased hole, or to ledges and rugous boreholes when run in open hole. The centraliser is driven along the tubular in the opposite axial direction to that of the tubular motion, and is driven into the rings and/or collars. Additionally, when the tubular is rotated (a common procedure when running tubular downhole, converting drag friction to torque friction) the “nose” of the centraliser is forced against a stop-collar and the tubular rotated—thus causing the centraliser nose to act as a thrust bearing. If the centraliser deforms and rides over the collar, the stretched material may jam the centraliser, and possibly the tool or assembly against the borehole wall. This problem is sought to be addressed in WO 02/02904 (BRUNEL OILFIELD SERVICES). The problem is illustrated in cross-section in FIG. 1 thereof.        
The content of the aforementioned prior art document is incorporated herein by reference.
It is known that drill pipe connections can be “hard coated” with a material which is harder and more abrasive than the material from which the drill pipe is made so as to protect a drill string. This is because metals of similar hardness used for drill pipe and casing tend to gaul or “pick up”, i.e. cause wear between themselves due to their similar hardness. “Pick up” could be mitigated by coating the drill pipe connections with a harder abrasive material such as Tungsten Carbide. Such has the benefit of acting to reduce wear of the drill pipe—which can be used in a number of wells—but the disadvantage of causing wear to the casing. As wells become deeper this wearing problem becomes more critical. Further, by having a very hard material, such may start to wear off. Whilst it will reduce friction—as it acts to reduce the gauling process—it is not low friction. Typical field observed results of drill pipe steel versus casing friction are of the order of 0.25 to 0.35, even in an oil based or lubricated medium.
Even with improvements to the art, there remains a desire to improve upon known downhole tools. There is also a desire to seek to reduce the aforementioned trade-off requirements.
Accordingly, it is an object of at least one embodiment of at least one aspect of the present invention to obviate or at least mitigate one or more problems and/or disadvantages in the prior art.
It is also an object of at least one embodiment of at least one aspect of the present invention to improve over the known art.
It is also an object of at least one embodiment of at least one aspect of the present invention to provide an improved downhole tool or device having a friction factor of the order of ten times less than those known from the prior art, e.g. of the order of 0.100 or less, e.g. 0.030 to 0.070.